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The issues of voltage control and jurisdictional frequency response discussed in Section 3.2.1 lead directly to the need to maintain minimum numbers of conventional generators on-line in different parts of the AI system [78]. These are local constraints on generation from certain groups of generators and are shown in Table 4.4. As part of the same SOC document [78] there are also SOCs that limit maximum export capabilities from certain areas however these are due to constraints on the transmission system in relation to congestion and not issues related to grid stability, and therefore will not be discussed further.

It should be noted from Table 4.4, that the “ROI-System Stability, min no. on”

and “NI-System Stability, min no. on” could become a single-system wide constraint after the completion of the second North-South interconnector [116]. This is due to the two jurisdictional electricity systems of ROI and NI effectively becoming fully integrated and frequency response then being a system-wide issue.

Local SOCs are important in capturing the effects of maintaining certain levels of voltage control and jurisdictional frequency response as discussed in Section 4.5.2. Certain local SOCs also account for transmission grid limits, but are not examined here in detail. The local SOCs are presented in [78] and are shown in Table 4.4. From this a base-case scenario was developed from [78] in which likely changes to SOCs between the present day and 2020. The base case of SOCs developed is as follows:

4. METHODOLOGY: PLEXOS

IMPLEMENTATION 4.5 Modelling of system operational constraints

Table 4.4: System operational constraints required for grid stability

Constraint Currently Issue(s)

ROI-System Stability, min no. on 5 Frequency response

Replacement reserve, max OCGT 504MW Reserve

Dublin Generation, min no. on 2/3 (day/night) Voltage control ROI-SW Generation, min no. on 3/2 (day/night) Voltage control

Moneypoint, min no. on 1 Frequency/Voltage

NI-System Stability, min no. on 3 Frequency response

Replacement reserve, max OCGT 211MW Reserve

NI-NW Generation, min no. on 0/1 (if load>1.0GW) Voltage control Kilroot Generation, min no. on 1 (if load>1.4GW) Voltage control Kilroot Generation, min no. on 2 (if load>1.55GW) Voltage control

[78]

All island of Ireland system operational constraints

• Non-synchronous generation, is discussed in detail in Section 4.5.1.

• Inter-Area flow, in a limit on maximum transfer from ROI to NI and vice versa, is assumed to be 2000MW both ways due to the North-South interconnector being in place [9].

Northern Ireland system operational constraints

• System Stability, this constraint is modelled assuming that three of the following generators with SEM id codes C30, B31, B32, B10, K1, K2 must be on at all times.

• Replacement Reserve, this constraint is modelled assuming the combined generation output of NI OCGTs must be less than 211MW leaving a 100MW of spare capacity for replacement reserve at all times.

• North West Generation, this constraint is modelled assuming that Coolkeeragh (SEM id code CPS) must be generating when NI system demand exceeds 1000 MW. This is for voltage control issues in the north-west of NI.

• Kilroot Generation, this constraint is modelled assuming that for Kilroot’s two units that there must be at least one unit generating if NI system demand exceeds 1400 MW and both units are required to be on-line if NI system demand exceeds 1550 MW. This is for voltage control issues in the Belfast area.

• Ballylumford generation, this constraint is ignored due to assumptions that transmission grid restrictions that cause these constraints will be upgraded by 2020.

Investigation of factors driving the costs of operating the 2020 Irish power system with large-scale wind generation.

63 Edward V. Mc Garrigle

• Moyle Interconnector, this constraint is ignored due to assumptions that transmission grid restrictions in Scotland that cause this maximum export capacity constraint will be upgraded by 2020.

Republic of Ireland system operational constraints

• System Stability, this constraint is modelled assuming that five out of the following generators SEM id coded: AD1, ADC, DB1, HNC, HN2, MP1, MP2, MP3, PBC, TYC, WG1 and new unit GI4 (CCGT) must be on at all times.

• Replacement Reserve, this constraint is modelled assuming an increased allowing maximum OCGT generation of 1034MW which still keeps 300MW for replacement reserve provison due to the additional OCGT generation added by 2020. The following generators SEM id coded:

AT1, AT2, AT4, ED3, ED5, MRC, NW5, RP1, RP2, TP1, TP3, and new units Cahir or Culleen (OCGT), NO1, Caulstown (OCGT) are controlled by this constraint.

• Dublin Generation, this constraint is modelled assuming that at least three genertors by night and two by day must be on-line in the Dublin area, This is out the group of the following generators, SEM id coded:

DB1, HNC, HN2, PBC. This is for voltage control issues in the Dublin region.

• South West Generation, this constraint is modelled assuming that at least three generators by day and two by night must be on-line in the South West area, This is out the group of the following generators, SEM id coded: AD1, AD2, AT1, AT2, AT4, SK3, SK4, WG1, MRC and new unit GI4 (CCGT). This is for voltage control issues in the South West region.

• Cork Generation, this constraint is modelled assuming that the maxium generation in the Cork area can not exceed 880MW due to transmission system restrictions. The proposed Grid Link Project [148] is assumed not to be completed by 2020. The following generators SEM id coded:

AD1, AD2, AT1, AT2, AT4, WG1, MRC are controlled by this constraint.

• Moneypoint, this constraint is modelled assuming that for Moneypoint’s three units (SEM id coed MP1, MP2 and MP3) that there must be at least one unit generating at all times, in order to support the 400kV network.

4. METHODOLOGY: PLEXOS

IMPLEMENTATION 4.5 Modelling of system operational constraints

• The Hydro Smolt Protocol constraint is not included due to lack of data.